Oil and Gas production involves the separation of the produced hydrocarbons into gas, oil, and water flows. This process involves numerous, cascaded separators, as shown in the article titled, The Auger Platform Debottlenecking and Expansion of Fluid Handling Facilities, written by T. R. Judd and C. B. Wallace (SPE 36584), which is incorporated herein by reference. Often, the overall production rate of a platform is limited by the ability to process, i.e. separate, the produced fluids.
The details of optimizing the separation process are complex and highly empirical. Although the residence time of a gas/liquid mixture within a settling vessel (i.e. a separator) has a large influence in the quality of the separation process, this quality is also typically influenced by other factors, such as the composition the mixture, the fluid properties and the internal components of the separation equipment. Often, numerous chemical additives are used at various stages in the process to aid in the separation process, such as demisters, defoamers and emulsifier breakers. Furthermore, the complete separation process involves multiple stages of separators, compressors, heater exchangers and possibly other equipment, with the performance of each stage having an impact on the performance of the next stage. All in all, it is a very complicated, empirical, yet critical process in oil and gas production. Unfortunately however, the ability to optimize this process, for say maximum oil production, is hindered by the inability to effectively monitor the efficiency, or quality of the separation process on a real time basis.
A fluid flow process (flow process) includes any process that involves the flow of fluid through pipe, ducts, or other conduits, as well as through fluid control devices such as pumps, valves, orifices, heat exchangers, and the like. Flow processes are found in many different industries such as the oil and gas industry, refining, food and beverage industry, chemical and petrochemical industry, pulp and paper industry, power generation, pharmaceutical industry, and water and wastewater treatment industry. The fluid within the flow process may be a single phase fluid (e.g., gas, liquid or liquid/liquid mixture) and/or a multi-phase mixture (e.g. paper and pulp slurries or other solid/liquid mixtures). The multi-phase mixture may be a two-phase liquid/gas mixture, a solid/gas mixture or a solid/liquid mixture, gas entrained liquid or a three-phase mixture.
In certain flow processes, such as those found in the oil and gas industries, it is desirable to separate liquid (e.g., oil and/or water) and gas (e.g., air) components of a fluid. This is typically accomplished using a separator, which is an item of production equipment used to separate liquid components of the fluid stream from gaseous components. The liquid and gas components flow from the separator in separate legs (pipes), with the leg containing the gas component referred to as the “gas leg” and the leg containing the liquid component referred to as the “liquid leg”. Each of the legs typically includes a flow meter to determine the volumetric flow rate of the gas and fluid components, respectively, wherein the volumetric flow rate for the gas leg is commonly measured using an orifice plate. Additionally, the liquid leg may include a watercut meter for determining the percentage (or phase fraction) of water in the liquid flow to thereby determine the percentage of oil in the flow. In fact, in some separator configurations, the liquid components are separated into a “water leg” and an “oil leg”.
As is well known in oil and gas production, the carry-over of liquid into the gas leg of a gas/liquid separator commonly occurs, wherein the liquid typically takes the form of a mist comprised of small liquid droplets. This is undesirable because the liquid carry-over can result in a host of undesirable events depending in large part on the degree of carry-over that takes place. As such, in order to minimize the amount of liquid carry-over most separators have mist catchers designed to recover the liquid carried over. Furthermore, the carry-under of gas into the liquid leg (or oil leg and water leg) of the gas/liquid separator also commonly occurs in oil and gas production, wherein the gas is typically comprised of small bubbles forming entrained gas in the liquid.
Currently, the vast majority of the world's oil production is allocated using separator-based measurements, wherein test separators are used to determine individual well production and high pressure production separators are often used to allocate production from individual fields prior to the commingling of produced fluids for further processing. The accuracy of these measurements is based on the assumption of complete separation of the gas and liquids phases. Thus, the separation of the oil, water, and gas phases is a critical step in the processing of the hydrocarbon production streams. Separator designs range from large, horizontal vessels for three-phase oil/water/gas separation to compact two-phase liquid/gas separators. In all cases, accurate well test and custody transfer measurements depend on the complete separation of the liquid and gas phase, however in practice 100% separation is frequently difficult or impractical to achieve. As such, a small, but unknown, level of gas in liquid lines is common and can result in significant measurement errors in both flow rate and water cut. Furthermore, since the oil exists in the separator at or near vapor pressure, additional out-gassing can occur at low pressure points in the downstream processes.
However, the measurement of oil production includes many variables ranging from varying crude oil properties, water cut, and gas-oil ratios to varying production rates, pressures, and temperatures. Given this variability associated with oil production, completely separating the gas and liquid phases prior to measurement often becomes difficult, if not impractical, to achieve. While the variable amounts of gas present during the measurement of the liquid phase and the variable amounts of liquid present during the measurement of the gas phase are often small, the presence of these secondary phases cause the vast majority of gas and liquid flow meters used in separator applications to over-report the amount of product flowing through the lines. In fact, errors due to incomplete separation are often the largest source of error in well and field allocations measurements, resulting in a distortion of the reservoirs engineer's view of well-by-well production and introducing systematic errors into the fiscal allocation of production. It is contemplated that by directly measuring and compensating for secondary phases in separator outflows, measurement errors due to incomplete separation can be avoided.
Liquid Outlet of the Liquid leg
The volume of liquid flowing through the liquid outlet is typically measured using turbine meters, positive displacement or Coriolis meters, wherein the accuracy of the liquid flow rate measurement depends in large part on the conditioning of the liquid stream. Unfortunately, entrained gases present in the liquid typically cause the primary flow measurement device to over-report the volumetric flow rate and, where applicable, under-report the liquid density. Thus, the presence of entrained gases within a flow meter on a liquid outlet can be traced to one of two primary sources, either gas carry-under and/or gas break-out. The first primary source, gas carry-under, generally results from the presence of small gas bubbles being entrained in the liquid as it leaves the separator. Due to the physics of gravity (or centrifugal) separation, typically, only the smallest bubbles are carried-under with the volume fraction of gas carried-under increasing with increasing flow rates through the separator. As mentioned above, the second primary source of entrained gas at the measurement location is due to gas-breakout. Ideally, liquids exit a separator at saturated conditions, i.e. provided sufficient residence time in the separator, all the gas that will come out of solution at separator pressure and temperature has done so when the fluid exits the separator. This liquid, however, can still contain significant amounts of dissolved gases which will typically continue to ‘outgas’ from the liquid with further decreases in pressure below the separator pressure. Additionally, the pressure losses due to flow through the piping prior to measurement and pressure losses due to the flow measurement device itself can lead to additional outgasing prior to measurement.
Gas Outlet for Gas Leg
Furthermore, the liquid carry-over in the gas outlet from the separator is typically in the form of small liquid droplets entrained in a mist and can vary in amount greatly, wherein estimates of 2% to 3% of the liquid inlet rate are not uncommon. The impact of liquid carry-over is two-fold. Firstly the liquid droplets can cause differential pressure-based (DP) gas flow meters, i.e. orifice plates, v-cones, venturi's, to over-report the gas flow rate in proportion to the wetness. Secondly, depending on the gas-oil ratios and other parameters, the liquid rates passing through the gas leg can be a meaningful percent of the total liquid rates.
Thus, in all separation scenarios the ability to accurately determine oil and water flow rates depends on both flow rate and water cut measurements, wherein the liquid flow rate is typically made with a turbine, positive displacement or coriolis meter and the water cut is commonly measured using microwave or coriolis density. The challenge is to maintain the accuracy of these measurements when gas bubbles exist in the liquid. Flow rate measurements will, at a minimum, over-report the liquid flow by an amount equal to the volume percent of the gas present. For example, a 1% by volume gas results in a 1% error in the flow rate measurement. Even after all of the processing steps that are completed prior to a fiscal transfer measurement point, several tenths or more of a percent gas can remain resulting in significant financial impact. Moreover, the water cut measurement error due to gas carry-under is often the single largest measurement source of error. For example, a density or microwave measurement will report a higher than actual oil fraction when entrained gas exists in the stream resulting in an over reporting of the oil rate and an inaccurate well test. Driven by goals to reduce the size and cost of separators, many operators are using smaller two-phase liquid/gas separation devices for determining oil and water flow rates. Unfortunately however, existing methods and systems are unable to achieve the desired results.
Therefore, there is a need for a system and method to quantify the measurement errors associated with each leg of a separator and provide an accurate measurement of the oil, water and gas output from a well head or multiphase input flow. As described in greater detail hereinafter, the present invention provides for an accurate and real time measurement of flow process parameters, such as the liquid carry-over and/or the gas carry-under. As such, the present invention allows for the control and/or optimization of the separation process via controlling the disbursement of deformer/demister and/or by maintaining the separator at a preferred level.